1. Field of the Invention
This invention relates to a surfactant fluid and to a method for recovering petroleum from subterranean high temperature, high salinity water-containing petroleum formations using the fluid.
2. Description of the Prior Art
Petroleum is normally recovered from subterranean formations in which it has accumulated by penetrating said formation with one or more wells and pumping or permitting the petroleum to flow to the surface through these wells. Recovery of petroleum from petroleum containing formations is possible only if certain conditions exist. There must be an adequate amount of petroleum in the formation, and there must be sufficient porosity and permeability or interconnected flow channel throughout the formation to permit the flow of fluids therethrough if sufficient pressure is applied to the fluid. When the subterranean petroleum containing formation has natural energy present in the form of an underlying active water drive, or gas dissolved in the petroleum which can exert sufficient pressure to drive the petroleum to the producing well, or a high pressure gas cap above the petroleum within the petroleum reservoir, this natural energy is utilized to recover petroleum. Recovery of petroleum by utilizing natural energy is referred to as primary recovery. When the natural energy source is depleted, or in the instance of those formations which do not originally contain sufficient natural energy to permit primary recovery operations, some form of supplemental recovery process must be applied to the formation to extract additional petroleum. Supplemental recovery is frequently referred to in the literature as secondary or tertiary recovery, although in fact it may be primary, secondary or tertiary in sequence of employment.
Water flooding, commonly referred to as secondary recovery, involves the injection of water into the subterranean, petroliferous formation for the purpose of displacing petroleum toward the producing well. This is the most economical and widely practiced supplemental recovery method. Water does not displace petroleum with high efficiency, however, since water and oil are immiscible, and also because the interfacial tension between water and oil is quite high. Persons skilled in the art of oil recovery have recognized this weakness of water flooding and many additives have been described in the prior art for decreasing the interfacial tension between the injected water and the formation petroleum. For example, U.S. Pat. No. 2,233,381 (1941) disclosed the use of polyglycol ether as a surface active agent or surfactant to increase the capillary displacement efficiency of an aqueous flooding medium. U.S. Pat. No. 3,302,713 and U.S. Pat. No. 3,468,377 (1969) describe the use of petroleum sulfonates for oil recovery. Other surfactants which have been proposed for oil recovery include alkyl sulfates and alkyl or alkylaryl sulfonates.
The above described surfactants are satisfactory for surfactant flooding in petroliferous formations only if the formation water salinity is below about 5000 parts per million total dissolved solids. Petroleum sulfonate is a popular and desirable surfactant because of its high surface activity and low unit cost, although it also suffers from the limitation that it can be used only when the formation water salinity is less than about 5000 parts per million total dissolved solids. If the formation water salinity exceeds about 5000 parts per million total dissolved solids, petroleum sulfonates precipitate rendering them inoperative for oil recovery and in some instances causing plugging of the formation.
Many subterranean petroleum-containing formations are known to exist which contain water whose salinity exceeds 5000 parts per million total dissolved solids. Limestone formations are commonly encountered which contains highly saline water including polyvalent ions in a concentration from 200 to as high as 20,000 parts per million in the original connate water, and the formation water after the formation has been subjected to flooding with fresh water may have concentrations of calcium and/or magnesium from about 500 to about 15,000 parts per million.
Other petroleum formations are known to contain formation waters with salinities as high as 225,000 parts per million total dissolved solids. Since many surfactants taught in the art as being usable for oil recovery operations precipitate when exposed to aqueous environments having salinities greater than about 5000 parts per million total dissolved solids, such surfactants cannot be used in limestone or high salinity reservoirs. If an aqueous solution of petroleum sulfonate, for example, is injected into a reservoir containing high salinity water, the petroleum sulfonate precipitates immediately on contacting the high salinity formation water. In such a process, the flood water would have essentially no surfactant present in it to decrease the interfacial tension between water and petroleum and so little or no petroleum displacement is obtained. Furthermore, precipitated petroleum sulfonate plugs small flow channels in subterranean petroleum-containing formations decreasing the formation porosity and injectivity, thereby causing a substantial decrease in the oil displacement efficiency.
In U.S. Pat. No. 3,508,612, J. Reisberg et al, 1970, an oil recovery method employing a mixture of sulfonates, specifically petroleum sulfonates and sulfated, ethoxylated alcohol is disclosed which results in improved oil recovery in the presence of high salinity water; however, the polyethoxy sulfate hydrolyzes at temperatures greater than 125.degree. F.
Nonionic surfactants, such as polyethoxylated alkyl phenols, polyethoxylated aliphatic alcohols, carboxylic esters, carboxylic amides, and polyoxyethylene fatty acid amides, have a somewhat higher tolerance of salinity and polyvalent ions such as calcium or magnesium than do the more commonly utilized anionic surfactants. While it is technically feasible to employ a nonionic surfactant solution to decrease the interfacial tension between the injected aqueous displacing medium and petroleum contained in some high salinity formations, such use would not be economically feasible for several reasons. Nonionic surfactants are not as effective on a per unit weight bases as are the more commonly used anionic surfactants, and furthermore, the nonionic surfactants have a higher cost per unit weight than do the anionic surfactants. Moreover, polyethoxylated alkyl phenol nonionic surfactants exhibit a reverse solubility relationship with temperature and become insoluble at temperatures in the range of 80.degree. F to 180.degree. F depending on the degree of ethoxylation and fluid salinity, making them ineffective in many oil formations.
The use of certain combinations of anionic and nonionic surfactants in high salinity or hard water formations is also taught in the art. For example, U.S. Pat. No. 3,792,731 describes the use of anionic and nonionic surfactant in saline environments. U.S. Pat. No. 3,811,505 discloses the use of alkyl or alkylaryl sulfonates or phosphates and polyethoxylated alkyl phenols in hard water environments; U.S. Pat. No. 3,811,504 teaches the use of a three component mixture including an alkyl or alkylaryl sulfonate, a polyethoxylated alkyl phenol and a sulfated, ethoxylated surfactant in hard water environments. U.S. Pat. No. 3,811,507 teaches the use of a water soluble salt of a linear alkyl or alkylaryl sulfonate and a polyethoxyated alkyl sulfate in very hard water environments. All of the nonionic surfactants described therein are only effective under conditions where they are soluble, and all have cloud points from 80.degree. F to 180.degree. F depending on salinity and so are ineffective above their cloud points.
Other problems encountered in surfactant flooding operations of the type taught in the prior art include susceptibility of the surfactant to bacterial degradation in the formation, and serious scale deposition in the production well through which formation fluids and previously injected aqueous fluids are produced to the surface of the earth.
Thus, it can be seen that while many surfactants have been proposed for supplemental oil recovery use, there is a substantial, unfulfilled need for a surfactant composition usable in the presence of high salinity formation waters which may include calcium and/or magnesium in excess of 500 parts per million especially in formations hotter than 125.degree. F. There is an especially serious need for surfactant systems with the foregoing properties which are additionally resistant to bacterial degradation in the formation.